California has been making good progress toward its ambitious clean energy goals, and now the state may aim to get 100 percent of its electricity from renewable energy and zero-carbon sources by 2045.
But some challenges remain. An often-overlooked hurdle is interconnecting wholesale distributed generation (wholesale DG, or WDG) projects to the grid. WDG refers to distributed energy resources, often commercial-scale solar projects, that connect to the distribution grid and sell the electricity they produce to the local utility to serve local energy demand.
Interconnecting a WDG project in California is an unpredictable process that can be arduous and expensive, and can extend over years — adding uncertainty and extra costs to project development, and discouraging many projects from getting off the ground or even being considered. Fixing the WDG interconnection process will result in significantly more clean, local energy in the state.
While California has been steadily increasing its percentage of renewables, only about 17 percent of the renewable energy generation in the state comes from local solar. Large rooftops and parking lots can cost-effectively host solar generation right where the energy is needed, with no costly transmission lines and minimal environmental impact. But the vast majority of these sites remain untapped.
A Solar Siting Survey identified over 650 megawatts of technical solar siting potential of at least 1 megawatt on large rooftops, parking lots and parking structures in Alameda County, Calif. (considering smaller commercial-scale sites would uncover gigawatts' worth of additional siting potential)
Growing the amount of DERs generated at the local level will bring numerous benefits. Clean local energy helps utilities meet renewable energy and sustainability goals while containing costs and lowering administrative burdens. It also keeps energy prices low for consumers. And for communities, clean local energy provides a trifecta of economic, environmental, and resilience benefits.
California is doing well with retail DERs behind customer meters, for which there’s already an effective policy in place: net energy metering. NEM typically works best for residential installations — like rooftop solar on single-family homes — or other owner-occupied properties. Vital to NEM’s success in California is the fact that its interconnection process has been streamlined. But that’s not the case for WDG.
WDG represents an important piece of the puzzle, because NEM does not effectively address the commercial-scale solar segment, including non-owner-occupied properties, split-metered facilities, and sites with little on-site load. WDG is the market segment that Germany unleashed with its national feed-in tariff (FIT), propelling that country to become a global clean energy leader.
Germany’s solar deployments are almost entirely sub-2-megawatt projects in built environments, interconnected to the distribution grid.
During the decade following the introduction of its FIT, Germany deployed over 10 times more solar capacity than did California.
Predictable, streamlined procurement and interconnection radically reduced the costs to build clean local energy projects in Germany. If California had the efficiency of the German solar market, WDG solar would be the cheapest energy that could be procured on behalf of Californians, at 3 cents per kilowatt-hour — without any need for transmission, which by itself costs California ratepayers 3 cents per kilowatt-hour.
Another benefit of WDG is that while NEM projects are connected to the grid behind the customer meter, with the energy generated primarily used onsite by the customer, WDG projects are connected in front of the meter and serve the broad community.
In other respects, NEM projects and WDG projects can be very similar. They can be similarly sized and sited. And the power they generate remains within the distribution grid, obviating the need for long, expensive transmission lines, and saving ratepayers billions.
Given the electrical similarities, it would seem that WDG and NEM projects should be subject to similar interconnection processes. However, in comparison to the process for identically sized and similarly sited NEM projects, interconnecting WDG projects costs significantly more and is far less predictable.
NEM vs. WDG Interconnection
Average utility charges per project
NEM projects up to 1 MW
Standardized flat fee
WDG projects up to 1 MW
Costs are estimated case-by-case and subject to post-contract revision
In addition, it hasn’t been possible for WDG developers to reliably estimate interconnection costs prior to completing an application. Given that the costs incurred prior to being able to submit an application for a 1 megawatt project typically exceed $50,000, and upgrade costs are an average of $150,000 (but vary widely), this risk is just too great for most developers.
The Peninsula Advanced Energy Community Initiative, funded by a grant from the California Energy Commission and led by the Clean Coalition, studied the challenges of WDG interconnection and developed recommendations to streamline the process. PAEC is a groundbreaking initiative to streamline policies and showcase projects that facilitate local renewables and other advanced energy solutions.
Interconnection best practices
The Initiative’s report, Best Practices: Interconnection for Local, Commercial-Scale, Renewable Energy Projects, provides clear recommendations to streamline the WDG interconnection process in California, with a focus on projects of up to 1 megawatt. Recommendations include ways to improve the predictability, flexibility and objectivity of the process.
The report found that it typically takes a year and a half to interconnect a 1-megawatt WDG solar project through the Pacific Gas & Electric Fast Track program. By analyzing PG&E’s quarterly filings with the California Public Utilities Commission, the Clean Coalition was able to determine exactly where delays occurred, such as during site control, numerous project reviews, drawing up of contracts, and grid upgrade construction.
The report’s recommendations include:
More details can be seen in this webinar highlighting the PAEC report findings. These recommendations align with the goals of Assembly Bill 327, which required utilities to develop grid planning strategies and programs for deploying DERs, including at locations on the grid that can accommodate new local generation without expensive interconnection costs.
To replicate the streamlined NEM interconnection process, timing and pricing for qualified WDG projects, the PAEC Initiative worked with PG&E to design a Pilot for Testing Streamlined Interconnection Procedures. The pilot features:
In addition to streamlining the interconnection process for WDG projects, the pilot aims to reduce time and cost for interconnection review, and to encourage or incentivize project applications that deliver benefits such as mitigating local grid needs or constraints.
By adopting the PAEC recommendations for streamlining WDG interconnection, utilities can improve the predictability, cost certainly, and timeline for interconnecting WDG projects to the grid in California and beyond. This will result in bringing more affordable clean local energy online — reducing greenhouse gas emissions; avoiding the need to build new, costly transmission infrastructure; and improving the resilience of the grid and our communities.
The WDG market represents a significant untapped opportunity for clean, local energy. To replicate Germany’s success, we must streamline WDG interconnection to unleash this market segment in California and throughout the United States.
Craig Lewis is the executive director of theClean Coalition, a nonprofit working to accelerate the transition to renewable energy and a modern grid. He has over 20 years of experience in the renewables, wireless, semiconductor and banking industries.
REC Solar’s project capacity is still catching up with its refined strategy, about six months after Duke Energy Renewables fully acquired the commercial solar developer.
According to GTM Research, the company installed 1.5 megawatts in Q1 2018, compared to 14 megawatts in the same time frame last year. It’s REC’s slowest quarter since mid-2015. Taken together with 2017 installations, REC’s ranking fell to No. 12 among commercial developers, compared to its third-place ranking at the end of 2017.
GTM Research Senior Solar Analyst Michelle Davis said the quarterly dip in installations doesn’t necessarily indicate trouble for REC, since commercial markets can be lumpy quarter-over-quarter. Instead, she said it further supports REC’s Duke-fostered pivot to focus on corporate offtakers and project ownership.
“Since REC focuses on the California commercial solar market, and has historically focused on agriculture customers, this low quarter points to potential saturation in that customer base and gives further justification to its shift toward corporate customers where there is likely more appetite for solar,” said Davis.
REC’s CEO Matt Walz — formerly of Duke Energy Renewables — said growing corporate interest in clean energy was the original impetus behind Duke’s investment in REC.
“The attraction of the corporates is one that’s growing. Year-over-year, you’re seeing more and more companies announce aggressive sustainability goals and higher standards, and you’re seeing more and more deals in the market. It’s a growing segment that doesn’t seem like it’ll slow down,” he said. “That shift in strategy, we saw that awhile back.”
Integrating REC reflects an evolution from within Duke Energy Renewables, as the company shifted away from serving other large utilities toward a focus on corporate buyers. Tammie McGee, lead communications manager for Duke’s commercial portfolio, said REC’s position in the market allows the company to work on small rooftop arrays for parking garages and headquarters, as well as larger-scale projects.
McGee points to two microgrid-as-a-service projects in Montgomery County, Massachusetts as examples of successful collaboration that have been carried out since the acquisition. The first, completed in April, is a 520-megawatt-hour project at Schneider Electric’s North American headquarters.
That type of project demonstrates the mutually beneficial relationship promised by the acquisition. Davis reported in a December research note that the acquisition offers each company the ability to cross-sell services, including Duke Energy Renewables’ microgrid and storage developments. Duke Energy Renewables currently owns and operates over 3,000 megawatts of large-scale battery, solar and wind projects. The two firms are also working on a 20-megawatt solar project at the Pearl Harbor-Hickam West Loch Navy base in Hawaii.
REC wants to avoid becoming a “single-solution-driven organization,” according to Walz. Together, he said Duke and REC offer an “umbrella of options” for corporate offtakers.
“In some ways, they’re entering the energy business,” Walz said. “We can be their energy partner.”
Since December, REC has discussed integrating sales and marketing efforts with Duke and experimented with how to better coordinate customer engagement. Davis suggested REC can reduce its operating expenses by taking advantage of Duke’s back-office setup, streamlining projects and helping REC focus on its customers. Nuances in the state-centric commercial solar market can slow down projects, but Duke’s backing may help REC adapt to those changes as it looks to enter new markets.
The company is also pivoting to more ownership under Duke’s influence. In 2018, REC began owning its own projects, and in Q1 GTM Research ranked the developer as a commercial solar asset owner for the first time. Although its small portfolio, under 500 kilowatts, puts REC in 10th place, Davis said the move aligns the company with the market.
“REC's shift is in line with a recent trend of more developers owning their projects. As competition tightens and distributed solar margins compress, developers want to capture more value from their projects by owning them,” said Davis.
In a November report on commercial solar ownership, Davis noted that the portfolios of owners that self-develop projects — such as NextEra and NRG — are growing faster than those that acquire projects. Developers including AES and Engie are also reaching into earlier development stages to take advantage of the potential to streamline development and control their project pipeline more directly.
In addition to Duke’s push toward ownership, McGee said the acquisition has synthesized REC’s nimble development with Duke Energy Renewables’ dependable financial strength. She said the duo’s “industry sophistication is demonstrated through the knowledge of not only how to run and build diversified energy systems, but also conveying a fundamental understanding of how wholesale power markets work.”
Upcoming quarters will determine whether that sophistication will translate into profit for each partner.
Few solar companies understand the importance of fast and efficient project commissioning as well as First Solar.
With a total of 17 gigawatts of projects installed across the globe, First Solar has experienced both easy and bumpy commissioning processes. Through all of that first-hand experience, First Solar has identified a handful of ways in which the speed of commissioning has the potential to impact the all-important economics of a project.
When done right, faster commissioning can translate into labor cost savings, particularly in states like California where union workers wages are relatively expensive. Rapid commissioning can also mean that revenue from the generation of electricity begin sooner rather than later.
“Faster commissioning may allow for the owner to receive more revenue from ‘test energy’ on the project,” said Troy Lauterbach, vice president of First Solar Energy Services. “Faster commissioning may allow the plant to reach COD [commercial operations date] earlier, therefore receiving revenue from the project earlier than expected.”
The good news: Project commissioning has been getting more efficient, just as modules, inverters, and actual construction times have improved over the past few years as well.
“We have seen the rate of commissioning improve as technology and methodology have evolved over the last decade,” said Lauterbach. “The rate of improvement in the speed of commissioning has a similar correlation to the rate of building the entire project.”
This matters in the solar industry more than ever. With competition fierce, margins thin and prices continuing to drop, the need to squeeze unnecessary costs out of every aspect of building a solar power plant has become increasingly important.
“The commissioning process is part of the capex investment for the whole PV plant, and it’s a significant enough part of the initial capex that easing commissioning through labor and material savings can really contribute to the overall capex savings of the system,” said Jiyong Lian, director of services for Huawei’s North America Smart PV Plant Solution.
Huawei, the world’s largest manufacturer of string inverters, is focused on making commissioning faster and more efficient in the future. Already, Huawei has used the power of string inverter design to speed commissioning, particularly in comparison to larger central inverters.
Even though EPCs have long been comfortable with large central inverters, their size and weight has often slowed down commissioning, in part due to their size, which requires installation on a concrete slab using heavy and expensive equipment. Commissioning with central inverters also requires that a technician from the inverter manufacturer be present — a requirement that can slow down and add expense to commissioning because of travel, scheduling and the added cost of paying the technician.
By contrast, large solar power plants using Huawei string inverters can be deployed using a block design approach that divides projects into 3- or 4-megawatt sections. Not only are string inverters light enough to be lifted into place without equipment, their commissioning is accelerated by the use of a cluster rack and an integrated transformer with both the AC and combiner box that reduces wiring and components. Commissioning for string inverters can go faster because they have fewer safety concerns.
“When you deal with the DC combiner boxes for central inverter solutions, the unit combiner box has potential shock hazards with arc flashes,” said Lian. “With us, during the installation the compartment remains closed because we have DC connecters built in under the inverter cabinet. When you connect the DC strings to the cabinet, there’s no shock hazard.”
The actual evolution of string inverter technology can also improve commissioning speed and efficiency.
“We can get a lot of power out of the same form factor. For instance, we launched the 100 KTL inverter with the same form factor as our 45 KTL,” Lian said. “It’s more than double the power density, which is more savings on capex because you can deal with a lot less AC combining effort.”
Although First Solar has limited experience commissioning string inverters, Lauterbach said the company’s initial experiences have been good. One aspect that is particularly appealing is the fact that there is no need to troubleshoot if one of the inverters isn’t working.
“You simply rip and replace with another inverter and continue the commissioning process,” he said. “At the end of the commissioning process, you just ship the non-functional inverters back to the OEM for troubleshooting.”
In the future, Lauterbach hopes to see faster commissioning through an increased use of plug-and-play equipment components. “Grid emulation is a key component to improvement in the future,” he said. “The more that components can leave the factory having been preconfigured, the faster the commissioning work in the field moves.”
Should California expand its energy markets to incorporate the rest of the Western United States?
This vital question for California’s energy future has been the subject of vigorous debate for years now. Supporters say it will allow California to access ever-cheaper wind and solar power from across the region, driving down energy costs and boosting jobs and the economy, while pressuring uncompetitive fossil-fuel-fired power plants to shut down.
Opponents fear it will drive renewables investment and jobs out of state, support coal plants owned by Rocky Mountain states utility PacifiCorp and others, and open California grid operator CAISO to losing its independence to determine its own clean energy and carbon reduction future.
The debate moved into sharp focus as of last month, when state legislators passed through a key committee a bill (AB 813) that would take the first steps toward creating a new regional energy market, giving it a chance to be brought to a vote before an August 31 deadline.
This week, the nonpartisan Next 10 Foundation released a report, A Regional Power Market for the West: Risks and Benefits, that weighs both sides of this debate, and largely finds that the benefits of grid regionalization outweigh the potential negative effects.
That’s largely because the report finds that the positive effects of regionalization — up to $1.5 billion per year by 2030 in reduced energy costs in California due to more competition, economies of scale, and cheap regional wind and solar power — outweigh the projections of losses for in-state renewable energy investment and jobs.
“Lower costs come from developing the best resources in the region, rather than restricting development to California,” report author Bentham Paulos wrote. “On the whole, studies say that regionalization would lead to greater job growth in California.”
As for the concerns that changing CAISO to a regional entity could undercut California’s control, the report notes that CAISO is already regulated by the Federal Energy Regulatory Commission (FERC). That fact that doesn’t change whether its board is appointed by California’s governor, as is true for CAISO today, or appointed via an independent commission, as is the case for the rest of the country’s grid operators.
“Because it has been responsive to state policy goals, some people think of it as a state agency, regulated by state policymakers. But it is not, and hasn’t been for almost two decades,” Paulos wrote. “A regional transmission organization, just like CAISO, would have to operate under a framework of FERC orders and federal law that require cooperation, free trade, and fair competition.”
In an interview this week, Paulos also noted that AB 813, if passed, “doesn’t just wave a magic wand and create a regional market.” Instead, it simply “sets the conditions under which California utilities can join a regional transmission organization,” he explained. “The California legislature can’t tell any other state what to do, but they can tell their utilities what to do. That’s the leverage that the legislature has, and that’s the reform mechanism” in play.
Jon Wellinghoff, former chairman of FERC, and Mike Florio, former California Public Utilities Commissioner, as well as members of groups both for and against regionalization, also advised Next 10 in its report.
The report was welcomed by groups like the Natural Resources Defense Council and Vote Solar, which have been arguing in favor of regionalization for the past three years.
However, Paulos also highlighted certain caveats to the report’s conclusions.
First, it does not include an analysis of a future in which California gets much of its energy from distributed energy resources such as rooftop solar PV, demand response or energy storage. That’s because, as he states in the report, “unfortunately, a distributed-intensive scenario was not included under the SB 350 studies mandated by the state to investigate a Western RTO, nor has it been adequately studied by other agencies, labs, universities, or think tanks.”
“On a technical level, a regional grid and a lot of DERs are really substitutes for each other — or could be,” he said in the interview. But without a DER-rich scenario to compare to the various bulk power-focused analyses included in the report, Next 10 was unable to measure how well DERs might serve to defer transmission-scale needs.
The Clean Coalition, one of regionalization’s biggest opponents at present — and a participant in the Next 10 report — has argued that California could obtain the same benefits of regionalization through DERs, without the risks and downsides.
Clean Coalition has also said expanding the regional Energy Imbalance Market, which has provided about $350 million in benefits by allowing California and other Western U.S. utilities that operate transmission systems to trade in a real-time market, is a more prudent move than pushing ahead with a regional authority.
Paulos also raised one more wild card in the regionalization analysis: the potential politicization of FERC by the Trump administration.
“Watching FERC these days is a real moving target,” he said. “All these Trump appointees, people aren’t really sure what they’re going to do. Is it going to be as politicized as the EPA? So far it hasn’t been,” he said, noting FERC’s unanimous rejection of Energy Secretary Rick Perry’s plan to force regulations that would guarantee payments for uncompetitive coal and nuclear plants in the name of grid resilience.
However, FERC’s recent split decision to force grid operator PJM to remake its capacity markets, in ways that could limit participation by state policy-supported resources including nuclear, wind and solar, has left many FERC watchers uncertain over its impact on clean energy policies across the country, he said.